Methods for Stimulating Oil or Gas Production Using a Viscosified Aqueous Fluid with a Chelating Agent to Remove Calcium Carbonate and Similar Materials from the Matrix of a Formation or a Proppant Pack

ABSTRACT

Methods for treating a subterranean formation can comprise introducing a treatment fluid comprising dicarboxymethyl glutamic acid (GLDA) or a salt thereof into a subterranean formation comprising a carbonate mineral, and at least partially dissolving the carbonate mineral in the subterranean formation using the GLDA. Treatment fluids containing GLDA or a salt thereof may be used to increase the permeability of a subterranean formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable

REFERENCE TO MICROFICHE APPENDIX

Not applicable

TECHNICAL FIELD

The invention generally relates to production enhancement to increasehydrocarbon production from a subterranean formation. More particularly,the invention relates to methods of treating a portion of a matrix of asubterranean formation or a proppant pack in a pre-existing fracture orperforation to increase permeability and enhance production, some ofwhich techniques are referred to as near-wellbore stimulation.

SUMMARY OF THE INVENTION

According to the invention, a method for treating a portion of asubterranean formation or a proppant pack is provided. In general, themethod comprises the steps of: (A) forming or providing a treatmentfluid comprising: (i) water; (ii) a chelating agent capable of forming aheterocyclic ring that contains a metal ion attached to at least twononmetal ions; and (iii) a viscosity-increasing agent; and (B)introducing the treatment fluid into the wellbore under sufficientpressure to force the treatment fluid into the matrix of the formationor the proppant pack.

Other and further objects, features and advantages of the presentinvention will be readily apparent to those skilled in the art when thefollowing description of the preferred embodiments is read inconjunction with the accompanying drawings

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

In general, the purpose of this invention is to improve delivery of achelating agent for production enhancement by increasing the viscosityof the treatment fluid. A chelating agent can be utilized to helpdissolve and remove carbonates and other minerals from the matrix of thesubterranean formation or the proppant pack. The concentration of thechelating agent is sufficient to help dissolve a substantial amount ofcarbonate material. The treatment fluid containing the chelating agentincludes a viscosity-increasing agent to help with placement of thefluid into the formation or proppant pack or to help with diversion ofthe treatment fluid. When the viscosity of the fluid is increased orgelled, the treatment fluid can provide better coverage and diversion,and thereafter be broken for flowback from the well. The treatment fluidcan be a single fluid that dissolves calcium/magnesium/iron carbonatesolids in the matrix of the near region surrounding a wellbore, apre-existing gravel pack, a pre-existing perforation, or a pre-existingfracture or that dissolves these solids in a proppant pack in apre-existing perforation or a pre-existing fracture. The treatment fluiddissolves such solids at a controlled rate and under a wide range ofconditions, especially over a broad range of pH and time. The inventioncan be advantageous because it can provide methods for treating thematrix of a subterranean formation or a pre-existing proppant pack forsuch purposes using treatment fluids that are non-acid containing andnon-corrosive.

The treatment methods according to the invention are expected to beeffective for applications associated with well completion andremediation, including: removal of carbonate scale from the formationand fractures in the formation; removal of carbonate from formations orproppant packs where the carbonate lines pore throats; stimulation forcarbonate containing formations where the use of acidic fluids might beproblematic, for example, in high-temperature formations due to reactionrates, or due to corrosion, etc. For a stimulation treatment, thepurpose is to improve the skin of the matrix of the formation over itsoriginal condition, and a greater depth of matrix penetration isdesirable. For a damage removal treatment, such as after a prior geltreatment or completion damage, less depth of penetration can besufficient (all else being equal), where the purpose of the damageremoval is to get the permeability of the matrix of the formation backtoward its original condition. According to a presently preferredembodiment, the treatment method is used as a remedial cleanup after aprior stimulation treatment.

As used herein, the words “comprise,” “has,” and “include” and allgrammatical variations thereof are each intended to have an open,non-limiting meaning that does not exclude additional elements or steps.

In general, the new approach is a method for treating a portion of asubterranean formation or proppant pack, the method comprising the stepsof: (A) forming or providing a treatment fluid comprising: (i) water;(ii) a chelating agent capable of forming a heterocyclic ring thatcontains a metal ion attached to at least two nonmetal ions; and (iii) aviscosity-increasing agent; and (B) introducing the treatment fluid intothe wellbore under sufficient pressure to force the treatment fluid intothe matrix of the formation or the proppant pack. As used herein, “intothe matrix of the formation or the proppant pack” means into the rockaround the wellbore, a pre-existing perforation, or a pre-existingfracture, or into the matrix of a proppant pack in a gravel pack in thewellbore, a pre-existing perforation, or a pre-existing fracture. Themethod is adapted to be used after drilling a wellbore, either duringcompletion or remediation of a well.

It is believed that the chelating agent in the treatment fluid can reactwith and dissolve calcium carbonate, magnesium carbonate, dolomite, ironcarbonate, and similar materials of the formation to increase thepermeability of the formation. It can also be used to help removecarbonate from formations where the carbonate lines the pore throats inthe matrix of the formation, whereby the permeability of the formationcan be increased and hydrocarbon production enhanced. It is desirable toallow the treatment fluid to contact the matrix of the formation or theproppant pack for a sufficient time to dissolve such carbonatematerials. CaCO₃ is known as limestone; and CaMg(CO₃)₂ is known asdolomite or dolomitic limestone, both of which are minerals that areoften present in subterranean formations or which may precipitate fromwater as scale in subterranean formations or proppant packs. Typicalscales are of calcium carbonate, calcium sulfate, barium sulfate,strontium sulfate, iron sulfide, iron oxides, iron carbonate, varioussilicates and phosphates and oxides, or any of a number of compoundsinsoluble or slightly soluble in water. Although it may not be expectedto dissolve all of the components of scale, the chelating agent can behelpful in removing calcium carbonate, magnesium carbonate, dolomite,iron carbonate, and similar materials of scale.

As used herein, to chelate means to combine a metal ion with a chemicalcompound to form a ring. “The adjective chelate, derived from the greatclaw or chela (chely-Greek) of the lobster or other crustaceans, issuggested for the caliper like groups which function as two associatingunits and fasten to the central atom so as to produce heterocyclicrings.” Sir Gilbert T. Morgan and H. D. K. Drew [J. Chem. Soc., 1920,117, 1456].

Preferably, the water further includes a water-soluble inorganic saltdissolved therein. The purpose of the inorganic salt can be, forexample, to weight the water of the treatment fluid or to make thetreatment fluid more compatible and less damaging to the subterraneanformation. It should be understood, of course, that a source of at leasta portion of the water and the inorganic salt can be selected from thegroup consisting of natural or synthetic brine or seawater. Inorganicsalt or salts can also be mixed with the water of the treatment fluid toartificially make up or increase the inorganic salt content in thewater. Alternatively for these types of purposes, a water-soluble saltreplacement can be utilized such as tetramethyl ammonium chloride (TMAC)and similar organic compounds.

It is a particular advantage of the method according to the invention tobe able to help remove carbonate and similar materials without the useof strongly acidic treatment compositions, that is, without the use oftreatment compositions having a pH less than 2. According to a preferredembodiment of the invention, the pH of the treatment fluid is equal toor greater than 2, which is above the pH of strong inorganic acids thathave been used to help dissolve and remove carbonate materials from theformation.

More preferably, according to the invention, the pH of the treatmentfluid is equal to or greater than 5, which is well above the pH of spentacid fluids used for the purpose of removing carbonate, where the pH ofan acid fluid is typically less than about 3.5. The compositions of thepresent invention can be used to help dissolve and remove carbonatematerials from the formation with less acidic compositions. In someapplications, acidic compositions can be damaging to the well orhydrocarbon production.

Most preferably, according to the invention, the pH of the treatmentfluid is in the range of 6-12, which can be used to avoid or reduce theuse of substantially acidic compositions in treating the formation. Itis important to note, of course, that different chelating agents workbetter in certain pH ranges than other ranges. Some chelating agents canbe effective in the higher pH ranges. One skilled in the art would alsorecognize the obvious advantage of using a non-acid fluid may reduce therate of corrosion.

In particular, the chelating agent is selected to be effective forchelating at least calcium ions. It is also highly desirable that thechelating agent is soluble in distilled water at standard temperatureand pressure at a concentration of at least 0.2 mole-equivalent forcalcium ions per liter of the distilled water. As a test for whether ornot the chelating agent would be effective for use in the presentinvention, it is believed that a solution of the chelating agent at aconcentration of 0.2 mole-equivalent for calcium ions per liter of thedistilled water should be effective for chelating at least 0.1 molecalcium ions per liter. Preferably, the test solution is effective whenadjusted to have a pH in the range of 5-6. More preferably, the testsolution is effective when adjusted to have a pH in the range of 6-8.One skilled in the art would recognize that similar tests can beperformed for other ions such as magnesium, iron, etc.

There are numerous examples of suitable chelating agents. For variousreasons including effectiveness, ready availability, and economicalcost, the chelating agent is preferably selected from the groupconsisting of ethylenediamine tetraacetic acid (“EDTA”),nitrilotriacetic acid (“NTA”), hydroxyethylethylenediaminetriacetic acid(“HEDTA”), diethylenetriaminepentaacetic acid (“DTPA”),propylenediaminetetraacetic acid (“PDTA”),ethylenediaminedi(o-hydroxyphenylacetic) acid (“EDDHA”), a sodium orpotassium salt of any of the foregoing, dicarboxymethyl glutamic acidtetrasodium salt (“GLDA”), a derivative of any of the foregoing or anycombination in any proportion thereof. It is to be understood, ofcourse, that a derivative may be employed provided that the substitutionof an atom or group of atoms in the parent compound for another atom orgroup of atoms does not substantially impair the function of thederivative relative to the parent compound. A derivative would alsoinclude compounds that do not have the functionality, but would regainfunctionality due to some process in use such as a reaction, hydrolysis,degradation, etc. The chelating agent is preferably at a concentrationof at least 0.01% by weight of the water. More preferably, the chelatingagent is at a concentration in the range of 1% to 80% by weight of thewater.

The viscosity-increasing agent would typically comprise a polymericmaterial. For various reasons including effectiveness, readyavailability, and economical cost, the polymeric material is preferablyselected from the group consisting of: guar gum and its derivatives,cellulose derivatives, welan gum, xanthan biopolymer and itsderivatives, diutan, and its derivatives, scleroglucan and itsderivatives, succinoglycan biopolymer and its derivatives, and anycombination of any of the foregoing in any proportion. Derivatives caninclude, for example, industrially manufactured chemical derivatives,bioengineered chemical derivatives, or naturally occurring derivativesproduced by mutated organisms producing the polymer. A preferred polymeris of the nature taught in U.S. Patent Application Serial No.20060014648, which is incorporated herein by reference in its entirety.

According to another aspect of the invention, the viscosity-increasingagent can advantageously comprise a viscoelastic surfactant. Oneperceived advantage of a surfactant gel is that it has much lesspotential for leaving a polymer residue. The viscoelastic surfactant maycomprise any viscoelastic surfactant known in the art, any derivativethereof, or any combination thereof. As used herein, the term“viscoelastic surfactant” refers to a surfactant that imparts or iscapable of imparting viscoelastic behavior to a fluid due, at least inpart, to the association of surfactant molecules to form viscosifyingmicelles. These viscoelastic surfactants may be cationic, anionic,nonionic, or amphoteric/zwitterionic in nature.

The viscoelastic surfactants may comprise any number of differentcompounds, including methyl ester sulfonates (e.g., as described in U.S.patent application Ser. Nos. 11/058,660, 11/058,475, 11/058,612, and11/058,611, filed Feb. 15, 2005, each of which is assigned toHalliburton Energy Services, Inc., the relevant disclosures of which areincorporated herein by reference), hydrolyzed keratin (e.g., asdescribed in U.S. Pat. No. 6,547,871 issued Apr. 15, 2003 to HalliburtonEnergy Services, Inc., the relevant disclosure of which is incorporatedherein by reference), sulfosuccinates, taurates, amine oxides,ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols (e.g.,lauryl alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fattyamines, ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate),betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropylbetaine), quaternary ammonium compounds (e.g., trimethyltallowammoniumchloride, trimethylcocoammonium chloride), derivatives of any of theforegoing, and any combinations of any of the foregoing in anyproportion.

Suitable viscoelastic surfactants may comprise mixtures of severaldifferent compounds, including but not limited to: mixtures of anammonium salt of an alkyl ether sulfate, a cocoamidopropyl betainesurfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodiumchloride, and water; mixtures of an ammonium salt of an alkyl ethersulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, acocoamidopropyl dimethylamine oxide surfactant, sodium chloride, andwater; mixtures of an ethoxylated alcohol ether sulfate surfactant, analkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkenedimethylamine oxide surfactant; aqueous solutions of an alpha-olefinicsulfonate surfactant and a betaine surfactant; and any combination ofthe foregoing mixtures in any proportion. Examples of suitable mixturesof an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkeneamidopropyl betaine surfactant, and an alkyl or alkene dimethylamineoxide surfactant are described in U.S. Pat. No. 6,063,738, issued May16, 2000 to Halliburton Energy Services, Inc., the relevant disclosureof which is incorporated herein by reference. Examples of suitableaqueous solutions of an alpha-olefinic sulfonate surfactant and abetaine surfactant are described in U.S. Pat. No. 5,897,699, therelevant disclosure of which is incorporated herein by reference.Examples of commercially-available viscoelastic surfactants suitable foruse in the present invention may include, but are not limited to,Mirataine BET-O 30™ (an oleamidopropyl betaine surfactant available fromRhodia Inc., Cranbury, N.J.), Aromox APA-T™ (an amine oxide surfactantavailable from Akzo Nobel Chemicals, Chicago, Ill.), Ethoquad O/12 PG™(a fatty amine ethoxylate quat surfactant available from Akzo NobelChemicals, Chicago, Ill.), Ethomeen T/12™ (a fatty amine ethoxylatesurfactant available from Akzo Nobel Chemicals, Chicago, Ill.), EthomeenS/12™ (a fatty amine ethoxylate surfactant available from Akzo NobelChemicals, Chicago, Ill.), and Rewoteric AM TEG™ (a tallowdihydroxyethyl betaine amphoteric surfactant available from DegussaCorp., Parsippany, N.J.).

According to a preferred embodiment of the invention, theviscosity-increasing agent is at a concentration in the treatment fluidthat is at least sufficient to make the viscosity of the treatment fluidgreater than water. More preferably, the viscosity-increasing agent isat a concentration in the treatment fluid that is sufficient to make theviscosity of the treatment fluid greater than 5 cP when measured at 511reciprocal seconds on a Fann 35A model viscometer with a number 1 springand bob. More preferably, the viscosity-increasing agent is at aconcentration in the treatment fluid that is sufficient to make theviscosity of the treatment fluid in the range of 10 cP to 100 cP whenmeasured at 511 reciprocal seconds on a Fann 35A model viscometer with anumber 1 spring and bob.

According to another preferred embodiment according to the invention,the viscosity-increasing polymeric agent is at a concentration of atleast 0.05% by weight of the water. More preferably, theviscosity-increasing agent is at a concentration in the range of 0.05%to 10% by weight of the water.

It is contemplated that it will sometimes be desirable to furtherincrease the viscosity of the treatment fluid. One technique for doingso is to crosslink a polymeric viscosity-increasing agent. According tosuch an embodiment of the invention, the treatment fluid furthercomprises a crosslinking agent to crosslink the polymeric material ofthe viscosity-increasing agent. A multitude of crosslinking agents forsuch purposes are known in the art. Preferably, the crosslinking agentis selected from the group consisting of: borate releasing compounds, asource of titanium ions, a source of zirconium ions, a source ofantimony ions, a source of aluminum ions, a source of periodate ions, asource of permanganate ions, and any combination thereof in anyproportion. According to a preferred embodiment, the crosslinking agentis at a concentration of at least 0.025% by weight of the water.According to a more preferred embodiment of the invention, thecrosslinking agent is at a concentration in the range of 0.025% to about1% by weight of the water. When the treatment fluid for use in themethods according to the invention includes a crosslinking agent, it canalso be desirable for the treatment fluid to further include a breakerfor the crosslinked agent.

According to another aspect of the invention, the treatment fluidpreferably further comprises a breaker adapted to break theviscosity-increasing agent. For example, when the viscosity-increasingagent is polysaccharide based, the breaker is selected to be effectivefor breaking a polysaccharide-based viscosity-increasing agent. Thebreaker can be, for example, an enzyme. By way of further example, whenthe polysaccharide-based viscosity-increasing agent includes starch, theenzyme is selected to be effective for breaking starch. Preferably, anenzyme breaker is at a concentration of at least 0.01 lb per 1000 gal ofthe water. More preferably, the enzyme breaker is at a concentration inthe range of 0.01 lb to 40 lb per 1000 gal of the water. As will beappreciated by persons of skill in the art, however, enzymes are oftenused as liquid compositions and that the above mentioned values are forfully formulated dry enzyme breakers that typically contain a largepercentage of fillers.

When a breaker is employed for the viscosity-increasing agent, thebreaker is at a concentration that is at least sufficient tosubstantially reduce the viscosity produced by the viscosity producingagent in the treatment fluid. In such case, a preferred embodiment ofthe method according to the invention includes the steps of allowingtime for the breaker to break the viscosity of the treatment fluid andthen flowing back the broken fluid from the wellbore.

For many types of viscosity-increasing agents, the breaker is preferablyan oxidizer selected from the group consisting of: a persulfate; aperborate; a bromate; a periodate; a chlorate; a chlorite; ahypochlorite, an organic peroxide; and any combination thereof in anyproportion. Further, the breaker is more preferably selected from thegroup consisting of a lithium, sodium, potassium, or ammonium salt ofany of the foregoing, and any combination thereof in any proportion. Theoxidizing breaker for breaking a viscosity-increasing agent internal tothe treatment fluid is preferably at a concentration of at least 0.01 lbper 1000 gal of the water. More preferably, such a breaker is at aconcentration in the range of 0.1 to 200 per 1000 gal of the water.

It is contemplated that in some applications of the methods according tothe invention, it may be desirable that the breaker be a delayed releasebreaker. One technique for making a delayed breaker is to coat orencapsulate the breaker to delay the release of the breaker into thewater. Another technique is to generate the breaker in situ over time orupon a change in pH of the treatment fluid.

According to a preferred embodiment of the invention, the method furtherincludes the step of after introducing the treatment fluid into thewellbore, allowing the viscosity of the treatment fluid to break to asubstantially lower viscosity fluid while down hole. According to afurther preferred embodiment, the method further comprises the step of:after allowing the viscosity of the treatment fluid to break, flowingthe fluid back from the well.

According to further embodiments of the methods of the invention, thetreatment fluid can further comprise a breaker to be carried by thetreatment fluid into the wellbore for breaking a viscosity-increasingagent that is external of the treatment fluid. According to theseembodiments, the breaker for the viscosity-increasing agent in thetreatment fluid is preferably at a concentration in an external aqueousfluid that is at least sufficient to substantially break the viscosityof the treatment fluid. The breaker for a viscosity-increasing agentthat is external to the treatment fluid can be the same or differentthan the breaker for the viscosity-increasing agent in the treatmentfluid. The additional or different breaker for breaking aviscosity-increasing agent external to the treatment fluid is preferablyat a concentration of at least 0.01 lb per 1000 gal of the water. Morepreferably, the breaker is at a concentration in the range of 0.1 lb to200 lb per 1000 gal of the water.

It is contemplated that the methods according to the invention caninclude foaming of the treatment fluid. According to these embodiments,the treatment fluid further comprises: an additive for foaming. Thetreatment fluid may be formed at a remote location and provided to thewell site for the treatment method, or it can be formed locally at thewell site. The treatment fluid preferably further comprises: asufficient gas to form a foam. As used herein, foam also refers tocommingled fluids. Preferably, the gas would be mixed with the otherconstituents of the treatment fluid at the well site to form a foamed orco-mingled fluid. According to a preferred embodiment of the invention,the gas is selected from the group consisting of: air, CO₂, nitrogen,and any combination thereof in any proportion. In applications of themethod utilizing a gas, typically, the gas is at a concentration in therange of 5% to 95% by volume of the water.

According to one aspect of the methods of the invention, the step ofintroducing the treatment fluid into the wellbore further comprises:introducing the treatment fluid at a rate and pressure below thefracture gradient of the subterranean formation. According to a furtherembodiment, the treatment fluid is applied such that the treatment fluidis introduced such that the proppant pack of a previously generatedfracture or gravel pack is treated.

As will be appreciated by those of skill in the art, in the context ofusing a method according to the invention to treat a portion of thesubterranean formation surrounding a wellbore, the permeability of thematrix of the surrounding formation would be expected to be relativelyhigh. According to a further embodiment, the treatment fluid is appliedsuch that the portion of the subterranean formation is a portionsurrounding the wellbore, and wherein the treatment fluid is introducedsuch that the portion surrounding the wellbore is expected to besaturated to a depth of at least 1 foot. More preferably, the treatmentfluid is applied such that the portion surrounding the wellbore isexpected to be saturated to a depth in the range of 1 foot to 3 feet. Ofcourse, it is recognized that desired or expected depth of penetrationinto the surrounding matrix of the formation will not necessarily beperfectly uniform. It is also recognized that the parameters fordesigning a treatment for a desired or expected depth of penetration arewell known in the art, including, for example, the length of thewellbore to be treated and the volume of treatment fluid injected intothe wellbore. One skilled in the art will recognize that a deeperpenetration may be desired or obtained in formations with higherpermeability.

In some situations, the permeability of the matrix of the surroundingformation would be expected to be relatively low. According to anotherembodiment, the portion of the subterranean formation is an areasurrounding a fracture extending into the formation, and the treatmentfluid is introduced such that the surrounding area is expected to besaturated to a depth of at least 0.1 inches. More preferably, thetreatment fluid is introduced into the wellbore under conditions suchthat the area surrounding the fracture is expected to be saturated to adepth in the range of 0.1 inches to 2 inches. One skilled in the artwill recognize that a deeper penetration may be desired or obtained informations with higher permeability.

According to another embodiment, the portion of the subterraneanformation is a perforation tunnel, and the treatment fluid is introducedsuch that the perforation tunnel and the surrounding area is expected tobe saturated to a depth of at least 0.1 inches. More preferably, thetreatment fluid is introduced into the wellbore under conditions suchthat the area surrounding the perforation tunnel is expected to besaturated to a depth in the range of 0.1 inches to 2 inches. One skilledin the art will recognize that a deeper penetration may be desired orobtained in formations with higher permeability.

One of skill in the art will further recognize that for the purpose oftreating the matrix of a proppant pack in a pre-existing gravel pack,fracture, or perforation, it may not be necessary or desirable topenetrate into the matrix of the surrounding formation.

According to another aspect of the methods of the invention, the methodsfurther comprise the step of: after the step of introducing thetreatment fluid, introducing a non-viscosified treatment fluid into thewellbore, wherein the non-viscosified treatment fluid comprises: waterand a chelating agent, without any substantial concentration of anyviscosity-increasing agent. According to this aspect, the viscosifiedtreatment fluid is capable of moving into zones of the subterraneanformation that have relatively higher permeability, thereby divertingthe non-viscosified treatment fluid into zones of the subterraneanformation that have relatively lower permeability. According to thisaspect, the injection pressure is preferably maintained from the step ofintroducing the treatment fluid to the step of introducing thenon-viscosified treatment fluid.

According to yet another aspect of the methods of the invention, themethods further comprise the step of: applying an afterflush fluid tothe portion of the subterranean formation. For example, the afterflushfluid can comprise: water, a gas, a brine, a hydrocarbon, or a mixturethereof.

An example of a treatment fluid for use in the methods according to theinvention was formed as shown in the following Table 1:

TABLE 1 Component Per 200 ml Per 1000 gallons Water 157.6 ml 788 US galsH4EDTA 98% 46.61 g 1987 lbs Potassium Hydroxide Solid 96% 20.95 g 870lbs Xanthan 0.96 g 40 lb/Mgal

The rheological properties of the example composition were measured on aFann Model 35 A viscometer as shown in the following Table 2:

TABLE 2 300 rpm 600 rpm Dial Reading at room temperature 21 29 DialReading at room temperature 29 35 after 4 hours at 175° F.

Therefore, the methods of the present invention are well adapted tocarry out the objects and attain the ends and advantages mentioned aswell as those that are inherent therein. While numerous changes may bemade by those skilled in the art, such changes are encompassed withinthe spirit of this invention as defined by the appended claims.

1.-27. (canceled)
 28. A method comprising: introducing a treatment fluidcomprising dicarboxymethyl glutamic acid (GLDA) or a salt thereof into asubterranean formation comprising a carbonate mineral; and at leastpartially dissolving the carbonate mineral in the subterranean formationusing the GLDA.
 29. The method of claim 28, wherein the pH of thetreatment fluid is equal to or greater than about
 2. 30. The method ofclaim 28, wherein the pH of the treatment fluid is equal to or greaterthan about
 5. 31. The method of claim 28, wherein the pH of thetreatment fluid is between about 6 and about
 12. 32. The method of claim28, wherein the treatment fluid further comprises water.
 33. The methodof claim 32, wherein the GLDA is present in the treatment fluid at aconcentration between about 1% and about 80% by weight of the water. 34.The method of claim 32, wherein the treatment fluid further comprises asurfactant.
 35. The method of claim 32, wherein the treatment fluidfurther comprises a component selected from the group consisting of asurfactant, a water-soluble inorganic salt, a water-soluble inorganicsalt replacement, a viscosity-increasing agent, a crosslinking agent, abreaker, a delayed release breaker, an enzyme, an oxidizer, an additivefor foaming, a gas, and any combination thereof.
 36. The method of claim28, wherein the carbonate mineral comprises a carbonate selected fromthe group consisting of calcium carbonate, magnesium carbonate,dolomite, iron carbonate, and any combination thereof.
 37. The method ofclaim 28, wherein the carbonate mineral comprises calcium carbonate. 38.The method of claim 28, wherein the carbonate mineral is present in aproppant pack.
 39. The method of claim 28, wherein the carbonate mineralis present in fracture.
 40. A method comprising: introducing a treatmentfluid comprising dicarboxymethyl glutamic acid (GLDA) or a salt thereofinto a subterranean formation; interacting the treatment fluid with thesubterranean formation; and increasing the permeability of thesubterranean formation with the treatment fluid.
 41. The method of claim40, wherein the pH of the treatment fluid is equal to or greater thanabout
 2. 42. The method of claim 40, wherein the pH of the treatmentfluid is equal to or greater than about
 5. 43. The method of claim 40,wherein the pH of the treatment fluid is between about 6 and about 12.44. The method of claim 40, wherein the treatment fluid furthercomprises water.
 45. The method of claim 44, wherein the GLDA is presentin the treatment fluid at a concentration between about 1% and about 80%by weight of the water.
 46. The method of claim 44, wherein thetreatment fluid further comprises a surfactant.
 47. The method of claim40, wherein the subterranean formation contains a carbonate mineral.